Harvest
posted a fourth quarter net loss of $44.7 million,
or $1.30
per diluted share, compared to a net loss of $4.0 million, or
$0.12
per diluted share, for the 2010 fourth quarter. � For the year ended December
31, 2011, Harvest's net income was $53.9 million,
or $1.37
per diluted share, compared with a net income of $15.4 million,
or $0.42
per diluted share, for 2010. �

The
fourth quarter results include exploration charges of $6.3 million, or
$0.18
per diluted share and dry hole expense of $49.7 million,
or $1.45
per diluted share. � The dry hole expense reflects costs incurred for the
Oman Block 64 wells in the amount of $9.7 million and
costs related to wells drilled in the Indonesia Budong-Budong Block during 2011
of $40.0
million. � Adjusted for these items, Harvest's
fourth quarter income was $11.3 million, or $0.33
per diluted share.

For the
year, Harvest incurred exploration charges of $13.7 million,
or $0.35
per diluted share, dry hole expense of $49.7 million,
or $1.26
per diluted share, and a loss on the extinguishment of debt of $9.7
million, or $0.25 per
diluted share. � Also related to the sale of the Utah assets
occurring in the second quarter, the Company reported income for the year from
discontinued operations of $97.6 million, or $2.48
per diluted share, for revenue, expenses, taxes and gain recognized.
� Adjusted for these items, net income for 2011 was $29.4 million, or
$0.75
per diluted share.

Petrodelta,
S.A. (Petrodelta), Harvest's Venezuelan affiliate, reported fourth
quarter income from operations of $74.0 million ($23.7
million net to Harvest's 32 percent equity interest under
International Financial Reporting Standards [IFRS]). � Petrodelta reported
fourth quarter earnings of $66.2 million ($21.2
million net to Harvest's 32 percent equity interest under
IFRS). � After adjustments to Petrodelta's IFRS earnings, primarily to
conform to accounting principles generally accepted in the United States of America
(USGAAP), Harvest's 32 percent share of Petrodelta's earnings was $14.6
million, a 44.1 percent increase over the same in 2010.

Petrodelta
reported income from operations for the year of $338.5 million ($108.3 million
net to Harvest's 32 percent equity interest under IFRS). � Petrodelta
reported earnings of $232.5
million ($74.4 million
net to Harvest's 32 percent equity interest, under IFRS). � After
adjustments to Petrodelta's IFRS earnings, primarily to conform to USGAAP,
Harvest's 32 percent share of Petrodelta's earnings was $57.7 million,
an 8.7 percent increase over 2010.

In
addition, total proved plus probable reserves on December 31, 2011
were 103.7 million barrels of oil equivalent (MMBOE), a decrease of 13 percent
from 2010, reflecting the sale of the Utah assets
which included 15.3 MMBOE; Venezuela had
total proved reserves of 43.3 MMBOE which was a decline of 13 percent from
2010, reflecting the reclassification of 16.1 MMBOE (37 percent) from proved to
probable in compliance with the Securities and Exchange Commission's "5
year rule from the date of original booking" and 2.6 MMBOE of production
in 2011. � Without the reclassification of the 16.1 MMBOE to probable,
proved reserves in Venezuela
would have increased 19 percent to 59.4 MMBOE. � All of the reclassified
reserves are scheduled to be drilled by 2016. � Probable reserves in Venezuela of
60.4 MMBOE are 13 percent higher than 2010, making total proved and probable
reserves unchanged from 2010.

On March 8,
2012, Harvest entered into exchange agreements with
certain existing noteholders of its 8.25 percent senior convertible notes
pursuant to which such noteholders agreed to exchange $15,984,000
principal amount of the notes for 2,875,357 shares of common stock, resulting
in an effective exchange price of $5.56 per share.
� In addition, in lieu of cash, Harvest agreed to issue to the noteholders
161,603 shares of common stock at $8.16 per share
in exchange for foregoing a one year interest make-whole of $1,318,680.
� After giving effect to the exchange, approximately $15,550,000
principal amount of the notes remain outstanding. � The exchange closed on
March� 14, 2012.

VENEZUELA

During
the twelve months ended December 31, 2011, Petrodelta
drilled and completed 15 successful development wells compared to 16
development wells in 2010. � Petrodelta produced approximately 11.39 MMBO
in 2011 compared to 8.56 MMBO during 2010, which represents an increase of 33
percent year over year. � In addition, Petrodelta sold 2.27 billion cubic
feet (BCF) of natural gas versus 2.20 BCF of natural gas, an increase of 3
percent over the same period in 2010. � Petrodelta produced an average of
31,205 barrels of oil per day (BOPD) during the twelve months ended
December� 31, 2011. � Currently, Petrodelta is operating three
drilling rigs and one workover rig. � Capital expenditures for development
drilling and infrastructure are estimated to be $137.5 million
in 2011 compared to $98.7
million in 2010.

On March 5,
2012, the Company commenced exclusive negotiations for a
specified time period with a third party for the possible sale of the Company's
32 percent interest in its Venezuelan asset, Petrodelta S.A.
� There can be no assurance that these negotiations will result in a
transaction to sell the Company's interests in Venezuela.

The
reserve report for the period ending December 31, 2011,
has been completed and a summary of the report is provided in Table 1 below.
� The reserve report for the Venezuela
fields assumes the average realized oil price in 2011 of $98.37 per
barrel, after adjustment for location and quality, less an adjustment of $32.10
per barrel for the impact of Venezuela Windfall Profit Tax, resulting in a net
realized oil price of $66.27. � The natural gas
reserves were based on a contractual price of $1.54 per
thousand cubic feet (MCF). � Table 2 below provides a comparison of the
estimated reserves by category between 2010 and 2011.

In 2011 the Company drilled one exploration well, the DRM-1, and
two appraisal sidetracks, the DRM-1-ST and the DRM-2ST, in the Dussafu Marin
PSC, in the offshore waters of Gabon.
� These wells were drilled with the Transocean Sedneth 701
semi-submersible drilling unit in approximately 380 feet of water.

The DRM-1 spud on April 28, 2011,
and drilled to test the potential of the pre-salt Gamba and Dentale Formation.
� The DRM-1 reached a vertical depth of 9,953 feet within the Upper Dentale
Formation. � Log evaluation, pressure data and samples indicate that
Harvest discovered approximately 55 feet of pay in a 90 foot oil column within
its primary objective, the Gamba Formation.

Subsequently the DRM-1 well was deepened to reach a TVDSS of
11,355 feet to test the prospectivity of the Middle and Lower Dentale
Formations. � Log evaluation, pressure data and a fluid sample indicate
that Harvest discovered a second oil accumulation with approximately 35 feet of
oil pay within the secondary objective of the Middle Dentale Formation.

The first appraisal sidetrack (DRM-1ST1) three quarters of a mile
to the southwest was drilled to a TD in the Upper Dentale of 11,562 feet (9,428
feet TVDSS) and found 19 feet of oil pay in the Gamba reservoir.

The second sidetrack (DRM-1ST2) half a mile to the northwest of
the original DRM-1 wellbore was drilled to a TD in the Upper Dentale of 10,615
feet (9,429 feet TVDSS) and found 40 feet of oil pay in the Gamba reservoir.

The Ruche discovery is the third oil discovery on the block, along
with Walt
Whitman and Moubenga. � The current estimate of
gross unrisked contingent resources for the three oil discoveries is 26 MMBBL.

Approximately 545 square kilometers of 3-D seismic acquired during
the fourth quarter is currently being evaluated in order to optimize future
drilling and development activities.

Harvest operates the Dussafu PSC, holding a 66.667 percent
interest.

Indonesia

Lariang Sub-Basin

The Lariang LG-1 well, the first of two planned exploration wells,
was spud on January� 6, 2011 in the Budong-Budong Block, West Sulawesi and
drilled to a depth of 5,311 feet. � Multiple oil and gas shows were
encountered within the secondary Miocene objective. � Wireline logs and
samples of reservoir fluids have confirmed the presence of hydrocarbons, trap
and seal. � Due to high formation pressures and losses of heavy drilling
mud into the formation, the well was plugged and abandoned for safety reasons on
April
8, 2011. � The primary Eocene targets had not yet
been reached, as the well was planned for a total measured depth of
approximately 7,200 feet.

Karama Sub-Basin

The Karama KD-1 well, the second exploratory well of a two-well
program on the Budong PSC was spud on June 20, 2011,
to drill and test the stacked Miocene and Eocene targets within a thrusted
anticline. � The well was initially drilled to a depth of 9,633 feet and
sidetracked after the drill string was severed. � The sidetrack KD-1ST was
initially drilled to a total depth of 11,880 feet and logged. � The
evaluation of cuttings, logs and sidewall cores demonstrated the presence of
oil over a 200 foot section of low permeability and low porosity clastic rocks
in the Miocene. � The oil shows have proven the existence of a working
petroleum system in the Karama Basin. �

On a sole risk operation basis, Harvest elected to deepen the well
to a final total depth of 14,437 feet to explore for the main Eocene objective.
� As the drilling operations reached the BOP pressure limits, the well
encountered both Oligocene and Eocene stratigraphy; however, the primary Eocene
reservoir target had not yet been reached. � Biostratigraphy indicates the
section at TD to be Eocene deep water shales. � Nearby within the basin
are a number of Eocene outcrops with known fluvial reservoir and source rocks,
along with oil and gas seeps. � The well was plugged and abandoned.
� Dry hole costs of $26 million were expensed in the
fourth quarter of 2011.

Since January
2012, after completion of drilling of the KD-1, all
information gathered from the drilling of the LG-1 and KD-1 is being evaluated
in connection with plans for the Budong PSC and overall corporate strategy.
� Based on this evaluation, it was determined that the original LG-1 well
bore would not be used for re-entry. � Since plans for the Budong PSC no
longer include re-entry of the LG-1 well bore, the drilling costs of $14.0
million related to the drilling of the LG-1 have been
expensed to dry hole costs as of December 31, 2011.
� Based on the multiple oil and gas shows encountered in both the LG-1 and
KD-1, we are working on an exploration program targeting the Pliocene and
Miocene targets encountered in the previous two wells.

Tately Budong-Budong N.V. is the operator
of the Budong-Budong Block. � Harvest owns a 64.4 percent working interest
in the Budong-Budong PSC.

Oman Block 64 EPSA

On October
29, 2011, Harvest spud the Mafraq South-1 (MFS-1)
exploration well onshore Oman.
� This was the first of a two-well exploratory program utilizing the MB
Petroleum Services LLC Rig #113 drilling unit. �

The MFS-1 exploration well was drilled to a total depth of 10,348
feet. � Although the quality of the Barik and the Amin reservoirs was
better than expected, the logs did not indicate the presence of hydrocarbons
within the stacked reservoir targets in the Barik, Miqrat and Amin reservoirs,
and the well was plugged and abandoned. � Drilling days to TD were 28 days
ahead of forecast resulting in reduced dry hole cost. � Harvest expensed $6.9
million in the fourth quarter of 2011.

On December
21, 2011, the Al Ghubar North-1 (AGN-1) exploration well
spud on the Qarn Alam Block 64, onshore Oman.
� This is the second of a two-well exploratory program utilizing the MB
Petroleum Services LLC Rig #113 drilling unit. �

The AGN-1 exploration well was drilled to a TD of 10,482 feet.
� Interpretation of the mudlog and wireline logs indicates no apparent
hydrocarbon saturations within the principal stacked Haima
targets in the Barik, Miqrat and Amin reservoirs. � The well was plugged
and abandoned on February
6, 2012 with gas shows.

The total dry hole cost for the well was $7.6 million, of
which $2.8
million was expensed in 2011 and the remainder in 2012.

Harvest has an 80 percent interest in Block 64 onshore Oman.
� Block 64 has an area of 3,874 square kilometers and was extracted from a
pre-existing block (PDO's Block 6) to accelerate exploration for gas and gas
condensate by the Omani Ministry of Oil and Gas.

UNITED
STATES - Antelope Project � Utah

On May
17, 2011, the Company completed the sale of its oil and
gas assets in Utah's Uinta
Basin to an affiliate of Newfield Exploration Company (Newfield).
� The Company received cash proceeds of approximately $217.8
million which reflects increases to the purchase price
for customary adjustments and deductions for transaction related costs.
� The sale had an effective date of March 1, 2011.
� The net proceeds from the sale were approximately $205.0 million
after deductions for transaction related costs.

Corporate and Financial Reporting

Debt

On May
17, 2011, Harvest repaid the $60.0 million
term loan facility with MSD Energy Investments Private II, LLC, an
affiliate of MSD Capital, L.P.
� The repayment included the repayment of the principal, accrued interest,
and other fees related to the early repayment of the debt and repurchase of
certain warrants. �

In October of 2011, approximately $500,000 of the
8.25 percent senior convertible notes was converted into common stock at the
predetermined conversion rate, leaving approximately $31.5 million of
the debt facility outstanding.

On March
8, 2012, Harvest entered into exchange agreements with
certain existing noteholders of its 8.25 percent senior convertible notes
pursuant to which such noteholders agreed to exchange $15,984,000
principal amount of the notes for 2,875,357 shares of common stock, resulting
in an effective exchange price of $5.56 per share.
� In addition, in lieu of cash, HNR agreed to issue to the noteholders
161,603 shares of common stock at $8.16 per share
in exchange for foregoing a one year interest make-whole of $1,318,680.
� After giving effect to the exchange, approximately $15,550,000
principal amount of the notes remain outstanding. � The exchange closed on
March� 14, 2012.

Financial Reporting

During the fourth quarter of 2011, we identified an error in our
consolidated financial statements for the year ended December 31, 2011
related to the income tax expense on the gain on the sale of the Antelope
Project.� The tax basis used at September� 30, 2011 in
calculating the tax expense was incorrect.� The reconciliation of the tax
basis to the book basis of the Antelope Project resulted in a
reduction of the income tax payable on the gain on the sale of the Antelope
Project of $5.5
million ($2.0 million of
the income tax benefit should have been recorded in the second quarter of 2011
and $3.5
million should have been recorded in the third quarter of
2011).� The reduction in income tax payable was offset by additional income
tax expense related to tax benefits on equity compensation of $2.5
million. These items were corrected by increasing Income
from discontinued operations for the 12 months ended December 31, 2011.
�

Additionally, during the fourth quarter of 2011, we identified an
error related to the deferred tax adjustment in reconciling our share of
Petrodelta's net income reported under IFRS to that required under
USGAAP.� The 2011 impact was a reduction in Net income from
unconsolidated equity affiliates of $0.4 million net
to our 32 percent equity interest. �

The cumulative effect of these corrections increased Harvest's net
income by $2.6
million for the year 2011.�

Reserves Disclosure

The proved, probable and possible reserves included herein were
prepared by Ryder
Scott and conform to the definitions as set forth in the
Securities and Exchange Commission's (SEC) Regulations Part 210.4-10(a).
� The hydrocarbon prices used are based on SEC price parameters
using the average prices during the 12-month period prior to the ending date of
the reserve report, determined as the unweighted arithmetic averages of the
prices in effect on the first day of the month for each month within such
period, unless prices were defined by contractual arrangements. � Reserves
are "estimated remaining quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations." � All reserve
estimates involve an assessment of the uncertainty relating to the likelihood
that the actual remaining quantities recovered will be greater or less than the
estimated quantities determined as of the date the estimate is made. � The
uncertainty depends chiefly on the amount of reliable geologic and engineering
data available at the time of the estimate and the interpretation of these
data. � The relative degree of uncertainty may be conveyed by placing
reserves into one of two principal classifications, either proved or unproved.
� Unproved reserves are less certain to be recovered than proved reserves
and may be further sub-classified as probable and possible reserves to denote
progressively increasing uncertainty in their recoverability. �

Proved oil and gas reserves are those quantities of oil and gas
which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible from a given date forward.
� If deterministic methods are used, the SEC has defined
reasonable certainty for proved reserves as a "high degree of confidence
that the quantities will be recovered." � Probable reserves are
"those additional reserves that are less certain to be recovered than
proved reserves but which, together with proved reserves, are as likely as not
to be recovered." � Possible reserves are "those additional
reserves which are less certain to be recovered than probable reserves"
and thus the probability of achieving or exceeding the proved plus probable
plus possible reserves is low.

The
reserves included herein were estimated using deterministic methods and
presented as incremental quantities. � Under the deterministic incremental
approach, discrete quantities of reserves are estimated and assigned separately
as proved, probable or possible based on their individual level of uncertainty.
� Because of the differences in uncertainty, caution should be exercised
when aggregating quantities of oil and gas from different reserves categories.
� Furthermore, the reserves and income quantities attributable to the
different reserve categories that are included herein have not been adjusted to
reflect these varying degrees of risk associated with them and thus are not
comparable.

Reserve
estimates will generally be revised only as additional geologic or engineering
data become available or as economic conditions change. � For proved
reserves, the SEC states that "as changes due to increased
availability of geoscience (geological, geophysical, and geochemical), engineering,
and economic data are made to the estimated ultimate recovery (EUR) with time,
reasonably certain EUR is much more likely to increase or remain constant than
to decrease." � Moreover, estimates of proved, probable and possible
reserves may be revised as a result of future operations, effects of regulation
by governmental agencies or geopolitical or economic risks. � Therefore,
the proved, probable and possible reserves included in this report are
estimates only and should not be construed as being exact quantities, and if
recovered, the revenues therefrom, and the actual costs related thereto, could
be more or less than the estimated amounts.

Non-GAAP
Financial Measures

In this
press release, Petrodelta's EBITDA disclosure is not presented in accordance
with accounting principles generally accepted in the United States
(GAAP) and Petrodelta's financials are not intended to be used in lieu of GAAP
presentations of net income or cash flows from operating activities.
� EBITDA is presented because we believe it provides additional
information with respect to both the performance of our fundamental business
activities as well as our ability to meet our future capital expenditures and
working capital requirements. � We also believe that financial analysts commonly
use EBITDA to analyze Petrodelta's performance. � Although we present
selected items that we consider in evaluating our performance, you should also
be aware that the items presented do not represent all items that affect
comparability between the periods presented. Variations in our operating
results are also caused by changes in volumes, prices, exchange rates and
numerous other factors. These types of variations are not separately identified
in this release, but will be discussed, as applicable, in management's
discussion and analysis of operating results in our Annual Report on Form 10-K
for the year ended December
31, 2011.

A reconciliation of EBITDA to net income and cash flows from
operating activities for the periods presented is included in the tables
attached to this release.

Conference call

Harvest will hold a conference call at 10:00 a.m. Central Daylight Time on
Thursday, March� 15, 2012, during which management
will discuss Harvest's 2011 fourth quarter and year end results. The conference
leader will be James A. Edmiston,
President and Chief Executive Officer. � To access the conference call,
dial 719-325-2207 or 888-523-1208, five to ten minutes prior to the start time.
� At that time you will be asked to provide the conference number, which
is 8284460. � A recording of the conference call will also be available
for replay at 719-457-0820, passcode 8284460, until 3:00 p.m. CDTMarch 20,
2012.

The Company intends to file its 2011 Form 10-K with the Securities
and Exchange Commission on Thursday, March 15, 2012.
� A copy of the Form 10-K will be available on the Company's website at www.harvestnr.com.

The conference call will also be transmitted over the internet
through the Company's website at www.harvestnr.com.
� To listen to the live webcast, enter the website fifteen minutes before
the call to register, download and install any necessary audio software. For
those who cannot listen to the live broadcast, a replay of the webcast will be
available beginning shortly after the call and will remain on the website for
approximately 90 days.

About Harvest Natural
Resources:

Harvest
Natural Resources, Inc., headquartered in Houston, Texas,
is an independent energy company with principal operations in Venezuela,
exploration assets in Indonesia, West Africa, China and Oman and
business development offices in Singapore and
the United Kingdom.
� For more information visit the Company's website at www.harvestnr.com.